Load growth coupled with aging transform ers is a disaster wait ing to happen

EVENTSEVENTSRISK ASSESSMENT

TRANSFORMERS MAGAZINE | Volume 3, Issue 396

ABSTRACT Infrared Thermography, Ultrasonic Noise Analysis, Partial Discharge De­tection, Dissolved Gas Analysis, Vi­bration Analysis – all these techniques are great stand­alone diagnostic tools; however, when used properly, combining the data obtained through each technique, an incipient fault can be identified long before it degrades the insulation and creates a failure.

This paper will provide guidance in setting up a complete Predictive Main­tenance program to be able to provide owners of oil­filled power transform­ers (4 kV and up), i.e. utilities, re­fineries, military, mining, etc., with a complete health report and condition assessment of critical oil­filled power transformers and ancillary substation components. The testing described in this paper is done on energized, fully loaded transformers.

Author’s vast experience with doing Partial Discharge testing reveals that nearly 80 % of all oil­filled power transformers exhibit some PD. This low level PD activity is not detrimental to the health of the transformer. It is usually a burr or sharp corner that is producing the activity. I consider this just nuisance PD and most times it continues for the entire life of a trans­former without a failure related to PD.

KEYWORDSPartial Discharge, Transformer Con­dition Assessment, Risk Analysis Tool

1. Introduction

I write this article from pure experience, having performed transformer mainte-nance for many years at a major utility, and then being part of an Electric Power Research Institute (EPRI) team tasked with developing a Predictive Maintenance (PdM) process for transformers and sub-station components. History and expe-rience have proven that there is no magic bullet for maintaining transformer health. Doing annual or periodic inspections is well worth the effort, but common sense thinking leads me to believe that installing full-time monitoring on critical tier 1 assets is probably the best way to avoid an unex-pected failure. But not all transformers me-rit the same level of attention. Utilities and refineries have many transformers with varying complexity and purpose. I recom-mend rating each one and assigning them in one of the three following tiers.

Tier 1 transformers will get the highest lev el treatment; some will be outfitted with full-time Partial Discharge (PD) monitor-

Transformer lifecycle and risk assessment

ing and Dissolved Gas Analysis (DGA). Tier 2 and 3 transformers will rarely be chosen for full-time monitoring. The in-spection process for all three tiers must be thoughtfully applied. As transformer experts (substation teams), our job is to maintain the highest level of operational capability for our transformers and sub-stations. A coordinated program of online and portable monitoring must be used to make sure that we are doing our part. The criticality of each transformer in your care should be ranked and that ranking used to provide guidance to your PdM team on just what is the correct level of moni-toring. The lack of a spare transformer and the lead time to have a new one built (typically 18 to 24 months), delivered on site, and installed is a consideration in the overall process.

The technology advances: Infrared Thermo-graphy, Ultrasonic Noise Analysis, Partial Discharge Detection, Dissolved Gas Analysis, and Vibration Analysis are all very high tech and necessary to deter-mine the health of our transformer fleet.

Determining the health of a transformer is a process that can make the difference between a transformer’s long life and an early death

Advanced transformer condition assessment

Part I

Jon L. GIESECKE

97 www.transformers-magaz ine .com

This article will provide knowledge about the latest methods and guidance in setting up a quality program. The goal is to be able to give a complete health report and condition assessment of critical oil-filled power transformers while they remain in service. Remember, the processes de-scribed in this paper are done on ener-gized, fully loaded transformers. No clear-ance or blocking is needed to accomplish these tasks. All tests are completely non-intrusive.

2. Analyzing data from history, coupled with field survey informationEach transformer owner has inform ation and data from each transformer under their care. This data is stored in file cabi-nets and computer programs and is read y to go to work for you. Mining the data

Each of the listed technologies is proven very effective; however, combining the in-formation from each technology will pro-vide solid answers to those who ask: How much life is left in my transformer? For many years I have dedicated my career path to the development and use of technology to determine the on-line condition assess-ment of power transformers and ancillary support equipment. Along with determining the remaining life is the issue of an action plan: repair, replace or continue to trend.

In the past twenty-two years since switch-ing from reactive to predictive trans-

former maintenance, the advancement of technology has exploded. However, the average utility is still doing transformer inspections as it did twenty-two years ago. Consider what information a transformer is willing to give up: it will tell you what is wrong with it if you are willing to listen.

• A transformer makes noise in both the sonic and the ultrasonic range;

• A transformer gives off heat which must be removed during operation;

• A transformer sends signals of impend ing insulation failure while in operation.

Table 1. Risk analysis grading tool

In the past 20 years since switching from reactive to predictive transformer main­tenance, the advancement of technology has exploded

Test year 2016 Nemx Nemx 1164 1164

Xfmr2 Xfmr 2 Xfmr3 Xfmr3 Xfmr4 Xfmr4 Xfmr5 Xfmr5 Xfmr6 Xfmr6 Xfmr7

Criteria Value Factor Value Factor Value Factor Value Factor Value Factor Value Factor Value

Serial number 6536968 R270131A G859918P G859918G M153429 S1689-01 S1689

Leaks N 0 N 0 N 0 N 0 N 0 N 0 N

Control wiring condition good Y 0 Y 0 Y 0 Y 0 Y 0 Y 0 Y

Winding power factor 0.48 0 0.49 0 0.55 -5 0.45 0 0.71 -5 0.44 0 0.45

Oil power factor @ 25°C 0.04 0 0.032 0 0.079 0 0.073 0 0.043 0 0.054 0 0.021

DGA condition code 3 -8 1 0 1 0 1 0 1 0 1 0 2

Full time DGA monitoring Y 0 N -5 N -5 N -5 N -5 N -5 N

Current gas generation - arcing Y -10 N 0 N 0 N 0 N 0 N 0 N

Current gas generation - thermal N 0 N 0 N 0 N 0 N 0 N 0 N

Oil acidity 0.02 0 0.02 0 0.02 0 0.02 0 0.02 0 0.01 0 0.01

Oil IFT 38.9 0 40.3 0 33.5 0 38 0 36.5 0 40.5 0 40.7

Oil dielectric (D877) 36 0 39 0 44 0 34 0 38 0 38 0 44

Water in oil (% Saturation) 3 0 65 -10 11.3 0 64.1 -10 5.4 0 8.4 0 5.9

PD burst interval in waveform 9 0 8 0 9 0 9 0 9 0 9 0 8

Arcing/sparking in waveform N 0 N 0 N 0 N 0 N 0 N 0 N

Lightning arrester test at full voltage N -5 Y 0 Y 0 Y 0 Y 0 Y 0 Y

Full time PD monitoring N -5 N -5 N -5 Y 0 Y 0 Y 0 Y

Manufacture date 1961 2008 1970 2012 1985 2005 2005

Age in years 55 -28.125 8 1.25 46 -22.5 4 3.75 31 -13.125 11 -0.625 11

Winding temperature (diff. from 55) 26 9 29 9 15 9 17 9 24 9 25 9 26

Highest top oil temp past year 45 0 42 0 38 0 40 0 35 0 45 0 40

Past thermal problems in DGA N 0 N 0 N 0 N 0 N 0 N 0 N

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TRANSFORMERS MAGAZINE | Volume 3, Issue 398

RISK ASSESSMENT

I have just inspected a critical 500 kV transform er that is sitting next to a failed transformer that is still smoldering. The operating transformer has partial dis-charge and arcing confirmed by DGA and by a specialized tool for doing on-line partial discharge measurements. It also captures arcing from the component under test. Using hind-sight, these trans-formers should have been outfitted with on-line monitoring which would have seen the catastrophic fault prior to the failure. This is a very serious condition which could result in the loss of electric power to a major portion of a small city.

The crucial nature, fragility, age, long lead time for major components, and the in-terconnection of the grid’s electrical sys-tem demand that the best maintenance approaches possible are applied to help ensure reliability.

4. Transformer life cycle management / risk management

Determining the condition, health and risk assessment of a transformer is a pro-cess that can be the difference between a transformer’s long life and an early death. Certain random failures can occur any time and with little or no warning, but as a transformer ages, there will be meas urable warning signs that somehow foretell the cause(s) of degradation or impending failure. The insurance industry states that insulation failure is the number one cause of transformer failure. So how do we de-termine the insulation quality while these transformers remain in service?

Examine what you are doing now!

A typical inspection program includes the following:

• Visual inspection• Dissolved gas analysis• Infrared outside control• Offline electrical testing

Note: Most utilities are doing this inspec-tion process, which has not changed in the past twenty years, or more.

An enhanced program could include these additional components:

• Partial discharge monitoring and ana-lysis (portable and on-line)

• Vibration analysis (determine core and coil assembly tightness)

• Sound level measurements (precursor to looseness)

• Grading method (transformer assess-ment and ranking tool)

• Template building (tier assignment done here)

Note: Adding these to your existing pro-gram could greatly reduce the unexpected failure rate.

Template building is a process where each transformer gets its own criterion sheet. A team of substation engineers gathers information on each transformer and decides what type of diagnostic data should be collected based on the critical-ity of each transformer. Tier assignment is done at this time. Tier one transformers are considered critical and should get the most attention. Tier two transformers are important but have redundancy and s pares. Tier three transformers are least important and could run to failure with-out major upset of the grid.

Combining data from several techniques will provide information

Very rarely will a failure occur without first revealing some small change that is detectable utilizing one or more tech-

that already exists, then combining it with current conditions allows us to pro-vide a grade for each transformer. This aids in determining the risk analysis and apply the correct surveillance for each transformer. Once the data is entered into the Excel spreadsheet (Table 1) from your available data source, maintaining the spreadsheet is simple. Data gathered while doing inspections is entered and any changes to the DGA is also entered. The age is changed on all transformers by one click of the mouse. There is no limit to the number of transformers that can be watched simultaneously. Grades are presented numerically as well as a letter, and a secondary grade is also given to in-dicate the highest possible score achiev-able when all deficiencies are corrected. The Excel spreadsheet contains formulas built into each cell that do the calcula-tions on the risk of each condition and how it affects the health and life expect-ancy of each transformer entered on the spreadsheet.

3. Do you think that waiting until a disaster strikes is the time to react?

The aging of the electrical infrastructure worldwide is a critical problem that each of you face. There is no way to get around that fact. As aging transformers continue to fail, a new level of awareness of the ma-gnitude of the situation becomes very clear. Load growth coupled with aging transform-ers is a disaster waiting to happen.

Many transformers fail unnecessarily. Accurate condition assessment and pro-per care of these valuable assets is needed now more than ever. With the transform-er fleet’s average age over 40 years and the new transformer fleet having a high-er-than-expected failure rate, a proac-tive approach to PdM is needed. Large power transformers are not off-the-shelf items and must be ordered one to two years in advance. The repair and replace-ment schedule is critical in most cases.

Certain random failures can occur any time, but as a transformer ages, there will be measurable warning signs that somehow fore tell the cause(s) of degradation or im­pending failure

The crucial nature, age, long lead time, and the interconnection of the grid’s electrical system demand that the best maintenance approaches possible are applied to help en­sure reliability

www.transformers-magaz ine .com 99

area where its sound reaches the tank wall, acoustic sensors could triangulate the exact spot of the fault. Fault sound reaches the tank wall about 90 percent of time. The remaining 10 percent of faults are too deep within the core and coil assembly, and the sound cannot be detected externally. In these cases, at least the severity of the fault and the fact that the transformer will require some work deep within the windings is deter-mined.

Acoustic tests have been used for many years to detect and locate partial dis-charges in power transformers, but the addition of the HFCT installed on the case ground of the subject transformer makes the process complete. It is more difficult to determine if a problem in an oil-filled transformer is related to mechanical or electrical malfunction utilizing acoustic sensors alone. Partial discharge testing using both acoustic sensors and an HFCT makes the deter-mination easy and increases the pro-tection factor for these utility industry assets.

Figure 1 shows acoustic and electrical PD activity obtained simultaneously. The

action. In a quest to determine unwanted activity, data can be gathered at a mo-ment in time, like taking a snapshot, or continuously over 24 hours or more, like making a movie. Movies generally tell a more complete story.

By adding the enhancing technologies to your TCA process, major failures will be averted. Major money will be saved, and a major safety feature will be built into every visit to the high-voltage transform-er yard.

Detecting acoustic and electrical problems on energized equipment

The following PD test described is used to determine the severity of an electrical fault using the burst interval of the PD pattern captured by the High Fre quency Current Transducer (HFCT). Then, if the source of the fault is located in an

Figure 1. Data showing classic partial discharge: the top screen shows Acoustic Emis­sion (AE); the bottom screen shows Electromagnetic Interference (EMI)

niques. Having stated this, information provided in this paper will direct and assist the reader starting an inspection process or expanding your existing PdM program.

This paper is designed to show the bene-fits of doing a complete Transformer Condition Assessment (TCA). Com-bining the data from various techniques will provide insight and understanding of often subtle, pre-failure signs. In ad-dition, a complete TCA will provide an as-accurate-as-possible gauge of the health of the transformer’s subsystems, including: pumps/cooling system, Load Tap Changer (LTC), De-energized Tap Changer (DETC) and lightning/surge arresters.

Partial Discharge (PD) is unwanted electrical activity. PD is similar to cor-ona and occurs at high voltage sine wave peaks. Most low-level PD activity is load-dependent. As the load increases, the voltage decreases. When the voltage de creases, the PD will decrease or disap-pear completely, and then return when the voltage returns to full value.

My experience with doing PD testing reveals that nearly 80 % of all oil-filled power transformers exhibit some PD. This low level PD activity is not detri-mental to the health of the transformer. It is usually a burr or sharp corner that is producing the activity. I consider this just nuisance PD and most times it con-tinues for the entire life of a transformer without a failure related to PD. How-ever, when true insulation breakdown occurs, both indicated and worsened by the PD, and reaches a point that it threat ens the life of a transformer, a decision must be made to remove the transformer from service.

Because PD is present in so many trans-formers, knowing the present condition of each transformer under your care is critical. Without systematic TCA, there is insufficient information available to con-fidently decide when to take appropriate

If the source of the fault is located in an area where its sound reaches the tank wall, acous­tic sensors could triangulate the exact spot of the fault

Asset managers need to know what to do and when to do it to be able to extend transform­er life or avoid impending failure

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Figure 3. Pulse Phase Graph showing no PD activity

Figure 4. Pulse Phase Graph showing small PD activity

Figure 2. The wave data indicating PD with a burst interval of 2.3 ms

top portion of the screen shows re corded acoustic sensor data, and the bottom shows data from the HFCT. In the ex-ample presented by this figure, the spac-ing of both the Acoustic Emission (AE) and HFCT sensors is 16 milliseconds, which is one full sinewave. The test equipment used for this data collection is the TP500A from PowerPD. The TP500 software has built-in bandpass filters which enable the user to filter out noise and pinpoint the PD, arcing or sparking. Source location of the fault is done using the acoustic sensors.

Severity criteria

Asset managers need to know what to do and when to do it to be able to extend transformer life or avoid impending fail-ure. The ability to trend the deterioration process aids the asset manager in de-ciding when to take action.

Figure 2 shows acoustic and PD data measured for amplitude and duration. This is easily trended by comparing subsequent test results under similar conditions. The top window in this fig-ure shows the AE bursts with sensor #2 (red) being closest to the source. The bottom window shows the PD burst captured from the case ground lead using the HFCT.

The signature captured by the HFCT, in the bottom portion, indicates a severe case of PD. The spacing between the end of one burst and the beginning of the next burst, called burst interval, is get-ting dangerously close to 2 milliseconds, clearly indicating a failure is imminent. Burst interval is critical information in determining the severity of PD.

Going deeper into the burst interval (60 Hz/milliseconds)

A review of test results for acceptance is performed using the following criteria based on burst interval:

• 8-7 milliseconds: satisfactory (many times 7 to 8 millisecond burst is found and is a non-damaging PD)

• 6-5 milliseconds: engineering review and evaluation needed

• 5-4 milliseconds: consider removal from service in near future

• 3-2 milliseconds: unsatisfactory, make plans to remove and repair now;

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Figure 6. Pulse Phase Graph showing dangerous PD activity

Figure 5. Pulse Phase Graph showing increasing PD activity requiring cautione xperience shows that 2 milliseconds is the critical point for catastrophic failure

• <2 milliseconds: removal from ser-vice, danger of catastrophic failure

Testing at repair facilities allows you to select the voltage you wish to use, any-where from 50 % to 150 %. There are times when the DGA is indicating PD but it is not possible to get any PD to be active until 110 % voltage is reached. Then the PD will begin, but it will drop off when we back down to 100 %. When the PD begins to deteriorate the insula-tion, the activity will increase at a lower voltage. If there is a small insignificant nuisance PD, it will have a burst interval of about 8 milliseconds. As the insula-tion deteriorates the PD begins at a l ower voltage and stops at a lower voltage. PD is a voltage related event. The Puls e Phase Graphs, shown in Figures 3 to 6, indicate varying severity of PD based on burst interval and not amplitude. As the PD occurs closer to the zero voltage crossing, the risk of failure increases. My experience has been that 2 milliseconds is the critical cut-off point prior to a cata-strophic failure. The charts in Figures 3 to 6 are hand-drawn to show examples of burst interval.

The wave data in Figure 2 indicates a PD with a burst interval of 2.3 milliseconds (ms). It was recommended to remove this unit from service.

Part II of this paper will discuss light-ning/surge arrester testing and vibration and sound level analysis, presenting the case studies and final conclusions.

There are times when the DGA is indicating PD, but it is not pos sible to get any PD to be ac­tive until 110 % voltage is reached. Once the PD begins, it will drop off when we back down to the rated voltage

AuthorJon L. Giesecke is an expert in combining technologies used in in-service inspection of high voltage oil-filled power transformers and substation diagnostics, with over 20 years of experience in transformer/substation predictive maintenance and over 25 years in substation electrical maintenance. Prior to forming JLG Associates LLC in 2006, he was employed by EPRI Solutions as a senior project

manager in the Substation Predictive Maintenance business area. Mr. Giesecke is also an ITC level III thermographer and has instructed at the FLIR ITC training center. He served on the board of directors of the International Society of Professional Thermographers, Inc. (ISPoT), and chaired the ethics committee. He was also responsible for PdM template development for fossil and nuclear applications. His career in electrical maintenance spans over 30 years with Exelon, formerly Philadelphia Electric Company. During his career with PECO, he held many positions, from helper to foreman, including 4 years of Doble testing, 2 years in outage planning, 2 years as training coordinator for the nuclear group, and 2 years as turbine/generator foreman.

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